It is often important to be able to determine the ratio of fluids in a two-component fluid system. For example, in the petroleum industry, fluid produced from a hydrocarbon formation normally includes both water and oil. The water may have originated naturally in the formation or it may have been introduced into the formation as a result of secondary recovery practices. In either case, it is necessary to know the oil content of the fluid since this information is needed for determining royalty payments, productivity measurements, the cost of lifting production fluid, equipment sizing and reservoir and well management.
A number of different ways of measuring the water/oil ratio have been suggested. Probably the most common method has been to simply introduce a sample of the fluid into a two- or three-phase test vessel where the fluids are allowed to separate from each other and from any dissolved gases, after which the individual phases are measured. This is not an entirely satisfactory method, however, because it is quite slow, requiring many hours and frequently days for the emulsions of oil, water and gas produced by wells to separate in the vessels. It may also be necessary to add expensive chemicals to enhance this separation. In addition, the apparatus is required to be semi-automatically operated, with data being acquired by visual and manual means, manually recorded and subsequently utilized in carrying out suitable mathematical calculations in order to obtain the information sought. The apparatus is necessarily large, expensive and cumbersome and is such that satisfactory operation requires great care and skill on the part of the technicians operating it. Also, use of such apparatus and its related method of testing production fluid for net oil content has frequently resulted in an error of plus or minus 10%, which is not acceptable by today's standards.
Another method is to measure the water content by measuring the electrical properties of the mixture, either by capacitance or resistance, and to obtain the oil content by subtracting the measured water content from the sample. Because the probes employed are extremely sensitive to numerous external factors, the measurements obtained in this method cannot be relied upon to yield an accurate ratio and must be frequently calibrated.
Another method is disclosed in U.S. Pat. No. 3,304,766, issued on Feb. 21, 1967, wherein the flow rate of a mixture of two liquids is measured by two different processes, one which determines the volumetric flow rate and one which determines the flow rate according to a different aspect of the mixture. The patent describes the use of a thermal instrument to determine the latter flow rate. In both cases the instrument is calibrated at 100% water, 100% oil and at various intermediate combinations of oil and water. With this information a set of curves are drawn, which are then used to interpolate the readings obtained for the fluid in question, allowing the percent of each constituent in the mixture to be estimated. Such a method does not permit rigorous calculations to be made, as only predetermined curves can be used. Further, it has inherent inaccuracies in sample definition, flow rate measurement and extrapolation. It is cumbersome and labor intensive, as calibration curves must be used for each different oil-water mix. The curves are good for only the system under investigation and must be known at the investigation temperature.
Another method is disclosed in U.S. Pat. No. 4,891,969, which issued on Jan. 9, 1990. This method is carried out by measuring the temperature increase in a fluid mixture resulting from the absorption of energy from a microwave field. The theory disclosed in the patent is based on the principle that the resulting rise in temperature of each component is proportional to its electrical thermochemical properties. In this process the level of microwave field power must be increased at smaller water fractions in order to obtain a significant temperature increase. Prior to using the test apparatus it must be calibrated with the water under investigation alone, with the oil under investigation alone and with a number of mixtures comprising intermediate oil/water ratios. Consequently, the test apparatus has problems similar to those previously mentioned. The calibration results are used to program a microprocessor to calculate the oil/water ratio from the various readings of properties taken during the testing of a fluid.
Despite the various methods proposed to determine the oil/water ratio of fluid produced from a petroleum well, no commercially demonstrated technology is available which will reliably, accurately and inexpensively determine the ratio. Further, most methods measure water content and are generally less accurate in measuring mixtures of fluids where water comprises 95% or more of the fluid, i.e., a one percent error at a 99% water cut is equal to a 100% error in the oil measurement. While this discussion has been primarily in connection with measurement problems relating to fluid produced from a hydrocarbon formation, it is noted that similar measurement problems exist in connection with other fluid systems.
It is an object of the present invention to provide a method for determining the ratio of fluids in a two-component fluid system which is accurate over the entire range of ratios from 0% to 100%, uses commonly understood thermodynamic and instrumentation technology, requires no chemicals for phase separation, lends itself to automation, is not space or capital intensive and provides accurate results. More specifically in connection with the petroleum industry, it is an object of the invention to provide such a method which is applicable to the determination of the ratio of water and oil in a system comprised of these two liquids. The ability to use such a method in the field in a remote location would be of further benefit.